This invention relates to an in-situ solvent-based process to produce bitumen from oil sand and heavy oil reservoirs.
A significant amount of bitumen in Alberta and other parts of the world is located either in thin, bottom water reservoirs or water sensitive sands which are not amenable to exploitation by steam based processes. A potential alternative for extracting these reservoirs is a solvent-based process. The advantages of the solvent-based processes are: little heat loss and limited water handling. The disadvantages are: high solvent cost and inherently low production rate limited by mass transfer of the solvent into the bitumen.
In general, many processes and methods utilizing a variety of solvents under a variety of temperature and pressure conditions have been developed to improve solubilization and production of hydrocarbons from reservoirs.
Lim et al in Canadian SPE/CIM/Canmet International Conference on Recent Advances in Horizontal Well Application, Mar. 20-24, 1994, disclose the use of light hydrocarbon solvents to produce bitumen for Cold Lake oil sand in three dimensional scaled physical modelling experiments. The results showed that the production rate of bitumen was significantly higher than what could be expected from molecular diffusion of the solvent into the bitumen. The author surmised that other mechanisms, probably solvent dispersion or fingering are important in mass transfer of solvent into bitumen.
Lim et al (1995) in Society of Petroleum Engineers paper no. SPE 302981 p. 521-528 discloses cyclic stimulation of Cold Lake oil sand with supercritical ethane through a single horizontal injector/producer well in a model system. Supercritical ethane enhanced the cyclic solvent gas process by improving the early production rate. This article directs the reader towards using supercritical ethane.
A problem that remains outstanding is to maximize extraction bitumen from oil sand and heavy oil reservoirs with maximum economy, minimum loss of solvent and to leave minimal residual bitumen in the oil sand and heavy oil reservoirs. A problem unaddressed to date is that of effective solvent distribution in a bitumen reservoir. If the solvent distributes too quickly throughout the reservoir there is a tendency for the solvent to be distributed along long thin solvent fingers penetrating into the reservoir from the point of injection. This leads to ineffective viscosity reduction and poor and difficult recovery of bitumen. If the solvent is insufficiently distributed in short thick fingers then solvent-bitumen contact is too limited to provide efficient bitumen extraction. We have developed an in-situ cyclic solvent-based process to produce bitumen from oil sand and heavy oil reservoirs which has advantages in maximizing solubilization and production rates.
We have found that careful choice of a viscosity reducing solvent and cyclic injection of this solvent at a pressure in the reservoir of above the liquid/vapor phase change pressure (saturation pressure) of the solvent, the pressure also being sufficient to cause geomechanical formation dilation or pore fluid compression, followed by mixing of the solvent with reservoir hydrocarbons under pore dilation conditions, followed by pressure reduction to below the liquid/vapor phase change pressure can be used to drive at least a fraction of the reservoir hydrocarbons from the reservoir.
The invention therefore provides a process for recovery of hydrocarbons from an underground reservoir of said hydrocarbons, the process comprising of:
(a) injecting a viscosity reducing solvent of a fraction of said hydrocarbons into said reservoir at a pressure in the reservoir of above a liquid/vapor phase change pressure of at least a fraction of said solvent; said pressure in said reservoir also being sufficient to cause geomechanical formation dilation or pore fluid compression, and then,
(b) allowing said solvent to mix with said hydrocarbons under pore dilation conditions, and then,
(c) reducing the pressure in said reservoir to below said liquid/vapor phase change pressure of at least said fraction of said solvent thereby demonstrating solvent gas drive of a fraction of said hydrocarbons from said reservoir; and then,
(d) repeating steps (a) to (c) as required.
In the context of this invention by solvent we mean a compound that has a liquid/vapor phase change pressure that is below the regularly used injection pressure of the reservoir and so is injected in the liquid phase. Preferably, the liquid/vapor phase change pressure should be close to the initial reserve pressure so that the operating reservoir pressure can easily be raised above the phase change pressure during injection and brought down below the phase change pressure during production. It also should be high enough so that the solvent vaporizes at the reduced pressures used for production so that solvent gas drive can be used to assist production. Suitable solvents include lower hydrocarbons, such as methane, ethane and propane, as well as CO2.
In the context of this invention by diluent we mean a liquid compound that can be used to dilute the solvent and can be used to manipulate the viscosity of any resulting solvent-bitumen mixture. By such manipulation of the viscosity of the solvent-bitumen (and diluent) mixture, the invasion, mobility and distribution of solvent in the reservoir can be controlled so as to increase bitumen production.
The diluent is typically a viscous hydrocarbon liquid, especially a C4 to C20 hydrocarbon or mixture thereof, is commonly locally produced and is typically used to thin bitumen to pipeline specifications. Pentane, hexane and heptane are commonly components of such diluents. Bitumen itself can be used to modify the viscosity of the injected fluid, often in conjunction with ethane solvent.
In preferred embodiments, the diluent may have an average initial boiling point close to the boiling point of pentane (36xc2x0 C.) or hexane (69xc2x0 C.) through the average boiling point (defined further below) may change with reuse as the mix changes (some of the solvent originating among the recovered viscous oil fractions). Preferably more than 50% by weight of the diluent has an average boiling point lower than the boiling point of decane (174xc2x0 C.). It is more preferred that more than 75% by weight, especially more than 80% by weight, and particularly more than 90% by weight of the diluent has an average boiling point between the boiling point of pentane and the boiling point of decane. In further preferred embodiments, the diluent has an average boiling point close to the boiling point of hexane (69xc2x0 C.) or heptane (98xc2x0 C.), or even water (100xc2x0 C.).
In additional preferred embodiments, more than 50% by weight of the diluent (particularly more than 75% or 80% by weight and especially more than 90% by weight) has a boiling point between the boiling points of pentane and decane. In other preferred embodiments, more than 50% by weight of the diluent has a boiling point between the boiling points of hexane (69xc2x0 C.) and nonane (151xc2x0 C.), particularly preferably between the boiling points of heptane (98xc2x0 C.) and octane (126xc2x0 C.).
By average boiling point of the diluent, we mean the boiling point of the diluent remaining after half (by weight) of a starting amount of diluent has been boiled off as defined by ASTM D 2887 (1997) for example. The average boiling point can be determined by gas chromatographic methods or more tediously by distillation. Boiling points are defined as the boiling points at atmospheric pressure.
In the context of the invention geomechanical formation dilation means the tendency of a geomechanical formation to dilate when pore pressure is raised to the formation minimum in-situ stress, typically by injecting a liquid or a gas. The formation in-situ stress is typically determined in a well test in which water is injected to the formation at low rates while bottom-hole pressure response is recorded. Analysis of the pressure response would reveal the conditions at which formation failure occurs. Pore fluid compression means just that, compression of a pore fluid (by pressure). In the field, the user can obtain pore fluid compression by multiplying pressure increase by fluid compressibility, which is a fluid property measurable in laboratory tests. Pore dilation refers to dilation of pores in rock or soil and simply means more loosely packed.
In a preferred embodiment, ethane is mixed with bitumen and the diluent and co-injected into the reservoir.